Additives for enhancement of oil flow

ABSTRACT

Use of pyrolysis oil (commonly referred to as bio-oil, bio-crude or tire oil) in combination with naphtha or liquified petroleum gas (LPG) can be utilized to reduce viscosity, increase API gravity and/or liquify paraffin and/or asphaltene in heavy crude oil at a reduced, overall percentage of naphtha. 
     Terpene, citrus isolates and/or non-ionic surfactants can be added to pyrolysis oil to form an additive. The additive can be combined with naphtha or LPG and added to heavy crude oil to reduce viscosity, increase API gravity, and/or liquify paraffin and/or asphaltene at a reduced, overall percentage of naphtha.

RELATED APPLICATIONS

This application claims priority to U.S. Patent Application Ser. No. 62/856,499, filed on Jun. 3, 2019; U.S. Patent Application Ser. No. 62/856,507, filed on Jun. 3, 2019; and U.S. Patent Application Ser. No. 62/856,515, filed on Jun. 3, 2019; which are specifically incorporated by reference in their entirety herein.

FIELD

The disclosure relates generally to the petroleum industry. The disclosure relates specifically to oil additives.

BACKGROUND

Transporting heavy crude oil by pipeline is difficult because of its high density and its viscosity of greater than 1,000 centipoise (cP). It also has very low mobility at the temperatures present at the reservoir and transportation. These issues are also a problem when using pumps or trying to put heavy crude oil into tankers.

Most solutions for the reduction of viscosity to allow for the flow of heavy crude oil through pipelines are accomplished with the use of various diluents, such as condensate, naphtha, diesel, kerosene, and/or light crude. Naphtha is favored as a diluent because it can be recycled from diluted heavy crude after transport and processing. The issues with condensate, naphtha, diesel, kerosene, and/or light crude are the amount of material required and for some of them, handling, storage and transportation issues due to the low flash point. These compounds also replace a volume of crude that could be transported through the pipeline.

Another solution is addition of a drag reducing agent, most commonly polyacrylamides, aqueous polyethylene oxide (PEO), or cellulose ethers such as carboxymethycellulose. Limiting factors of drag reducing agents include product cost, limiting turbulent flow, pipe-flow pressure gradients, and the possible negative effects at the refinery.

Yet another solution is emulsification of the oil with water. This option requires the necessary chemicals and equipment to create the emulsification. The biggest drawbacks are the amount of water required, resulting in an equal reduction of pipeline capacity, and the need to demulsify the oil prior to the refinery.

It would be advantageous to have a composition and method that decreases the amount of additive needed to reduce the viscosity of heavy crude oil. Further, it would be advantageous to have a composition and method that decreases the amount of naphtha needed to reduce the viscosity of heavy crude oil. It would also be advantageous to have a composition and method that increase the performance of pyrolysis oil (bio-oil) in heavy crude oil applications. Such a composition could aid in at least one of paraffin and/or asphaltene control, increase of API gravity, and viscosity reduction in heavy crude oil.

SUMMARY

An embodiment of the disclosure is a heavy crude oil additive comprising a naphtha and a pyrolysis oil. In an embodiment, the heavy crude oil additive comprising naphtha and pyrolysis oil reduces viscosity of the heavy crude oil. In an embodiment, the heavy crude oil additive comprising naphtha and pyrolysis oil increases the API gravity of the heavy crude oil. In an embodiment, the heavy crude oil additive comprising naphtha and pyrolysis oil liquifies paraffin and/or asphaltene in heavy crude oil.

An embodiment of the disclosure is a method of preparing a heavy crude oil additive comprising adding naphtha to pyrolysis oil.

An embodiment of the disclosure is a pyrolysis oil additive comprising at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants.

An embodiment of the disclosure is a method of preparing a pyrolysis oil additive for use in reducing the viscosity of a heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil; wherein the pyrolysis oil, the at least one pyrolysis oil additive, and a naphtha are added to heavy crude oil to reduce the viscosity of the heavy crude oil. In an embodiment, pyrolysis oil, the at least one pyrolysis oil additive, and the naphtha are added to the heavy crude oil at between 0.1 and 20%.

An embodiment of the disclosure is a method of preparing a pyrolysis oil additive for use in increasing API gravity in heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil; wherein the pyrolysis oil, the at least one pyrolysis oil additive, and a naphtha are added to the heavy crude oil to increase the API gravity of the heavy crude oil. In an embodiment, the pyrolysis oil, the at least one pyrolysis oil additive, and the naphtha are added to the heavy crude oil is added to between 0.1 and 20%.

An embodiment of the disclosure is a method of preparing a pyrolysis oil additive for use in liquifying a substance in heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil; wherein the pyrolysis oil, the at least one pyrolysis oil additive, and a naphtha are added to the heavy crude oil to liquify a substance in the heavy crude oil. In an embodiment, the pyrolysis oil, the at least one pyrolysis oil additive, and the naphtha are added to the heavy crude oil is added to between 0.1 and 20%. In an embodiment, the substance to be liquified is at least one selected from the group comprising paraffin and asphaltene.

An embodiment of the disclosure is a heavy crude oil additive comprising at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants; a naphtha; and a pyrolysis oil.

An embodiment of the disclosure is a method of reducing viscosity of a heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a naphtha to form a second additive; and adding the second additive to the heavy crude oil to reduce the viscosity of the heavy crude oil. In an embodiment, the additive to the heavy crude oil is added to between 0.1 and 20%.

An embodiment of the disclosure is a method of increasing API gravity in heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a naphtha to form a second additive; and adding the second additive to the heavy crude oil to reduce the viscosity of the heavy crude oil. In an embodiment, the additive to the heavy crude oil is added to between 0.1 and 20%.

An embodiment of the disclosure is a method of liquifying a substance in heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a naphtha to form a second additive; and adding the second additive to the heavy crude oil to reduce the viscosity of the heavy crude oil. In an embodiment, the additive to the heavy crude oil is added to between 0.1 and 20%. In an embodiment, the substance is at least one selected from the group comprising paraffin and asphaltene.

An embodiment of the disclosure is a pyrolysis oil additive comprising at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants; and a naphtha.

An embodiment of the disclosure is a heavy crude oil additive comprising a liquid petroleum gas (LPG) and a pyrolysis oil. In an embodiment, the heavy crude oil additive comprised of an LPG and pyrolysis oil reduces viscosity of the heavy crude oil. In an embodiment, the heavy crude oil additive comprised of LPG and pyrolysis oil increases the API gravity of the heavy crude oil. In an embodiment the heavy crude oil additive comprised of LPG and pyrolysis oil liquifies paraffin and/or asphaltene in heavy crude oil.

An embodiment of the disclosure is a pyrolysis oil additive comprising at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants; and an LPG.

An embodiment of the disclosure is a heavy crude oil additive comprising at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants; an LPG; and a pyrolysis oil.

An embodiment of the disclosure is a method of reducing viscosity of a heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a LPG to form a second additive; and adding the second additive to the heavy crude oil to reduce the viscosity of the heavy crude oil. In an embodiment, the additive to the heavy crude is added to between 0.1 and 20%.

An embodiment of the disclosure is a method of increasing API gravity in heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a LPG to form a second additive; and adding the second additive to the heavy crude oil to reduce the viscosity of the heavy crude oil. In an embodiment, the additive to the heavy crude is added to between 0.1 and 20%.

An embodiment of the disclosure is a method of liquifying a substance in heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a LPG to form a second additive; and adding the second additive to the heavy crude oil to reduce the viscosity of the heavy crude oil. In an embodiment, the additive to the heavy crude is added to between 0.1 and 20%. In an embodiment, the substance is at least one selected from the group comprising paraffin and asphaltene.

In an embodiment, the disclosed heavy crude oil additives comprising pyrolysis oil added to naphtha or LPG can also be blended and injected with field gas.

In an embodiment, the disclosed compositions can be further blended and injected with CO₂.

In an embodiment, the disclosed compositions can be blended and directly injected above the pump or downhole for treatment of production crude.

In an embodiment, the disclosed compositions can be blended with liquid natural gas (LNG) and injected above the pump or downhole for the treatment of production crude.

In an embodiment, the disclosed compositions can be blended with diesel fuels.

In an embodiment, the disclosed compositions can be blended using fractional oils from the pyrolysis oils.

In an embodiment, the disclosed compositions can be blended with zeolite and water soluble electrolyzed/hydrolyzed clinoptilolite fragments and nutraceutical, pharmaceutical, and environmental products based thereon.

In an embodiment, the disclosed compositions can be blended with at least one of nanoparticles, zeolite, and markers.

In an embodiment, the crude oil is bitumen.

In an embodiment, the disclosed compositions can be blended with distillate.

In an embodiment, the disclosed compositions can be blended with iron nanoparticles.

In an embodiment, the disclosed compositions can be blended with methane, ethane, propane, butane, and combinations thereof.

In an embodiment, the disclosed compositions can be blended with kerosene.

In an embodiment, the disclosed compositions can be blended with marine bunker fuels.

The foregoing has outlined rather broadly the features of the present disclosure in order that the detailed description that follows may be better understood. Additional features and advantages of the disclosure will be described hereinafter, which form the subject of the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

In order that the manner in which the above-recited and other enhancements and objects of the disclosure are obtained, a more particular description of the disclosure briefly described above will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. Understanding that these drawings depict only typical embodiments of the disclosure and are therefore not to be considered limiting of its scope, the disclosure will be described with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 depicts a graph of kinematic viscosity (centistokes) versus temperature for an additive of an additive of 95% naphtha and 5% pyrolysis oil added to crude oil at a ratio of 4%.

FIG. 2 depicts a graph of kinematic viscosity (centistokes) versus temperature for a VM+P (crude oil) naphtha additive was added to the crude oil at a ratio of 8%.

FIG. 3 depicts a graph of kinematic viscosity (centistokes) versus temperature for an additive of 3001-5 (95% naptha, 5% tire pyrolysis oil) added to crude oil at a ratio of 8%.

FIG. 4 depicts a graph of kinematic viscosity (centistokes) versus temperature for an additive of 3001-10 (90% naptha, 10% tire pyrolysis oil) added to crude oil at a ratio of 8%.

FIG. 5 depicts the colloidal instability index of four samples. The samples are CAN 10 (crude oil) (-diamond-); mix crude+naphtha (-square-); mix crude+UltraNaphtha (naphtha+pyrolysis oil) (-triangle-); and mix crude+UltraNaphtha (naphtha+pyrolysis oil) (-x-).

DETAILED DESCRIPTION

The particulars shown herein are by way of example and for purposes of illustrative discussion of the preferred embodiments of the present disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of various embodiments of the disclosure. In this regard, no attempt is made to show structural details of the disclosure in more detail than is necessary for the fundamental understanding of the disclosure, the description taken with the drawings making apparent to those skilled in the art how the several forms of the disclosure may be embodied in practice.

The following definitions and explanations are meant and intended to be controlling in any future construction unless clearly and unambiguously modified in the following examples or when application of the meaning renders any construction meaningless or essentially meaningless. In cases where the construction of the term would render it meaningless or essentially meaningless, the definition should be taken from Webster's Dictionary 3^(rd) Edition.

Additives can be added to heavy crude oil to achieve at least one of the following: reduce viscosity, increase API gravity, and liquefy substances in the heavy crude oil. In an embodiment, pyrolysis oil (bio-oil) and naphtha can be added to heavy crude oil for at least one of these purposes. In an embodiment, pyrolysis oil and LPG can be added to heavy crude oil for at least one of these purposes.

API gravity measures petroleum compared to water. An API gravity greater than 10 indicates that the petroleum is lighter than water and an API gravity less than 10 indicates that the petroleum is heavier than water. Therefore, API gravity is an inverse measure of a petroleum liquid's density relative to that of water.

In an embodiment, the additives provide flow improvement. Improvements include but are not limited to

-   -   Increased Oil & Gas Production     -   Rapid Clean-up     -   Does not require removal prior to refining     -   Reduces oil viscosity     -   Reduces Pumping Fees     -   Reduces under deposit corrosion     -   Does not require heating     -   Prevents redeposition     -   Provide demulsification in tanks

The heavy crude oil additives act as a flow diluent. The additives decrease the amount of diluent required for flow assurance. Therefore, the cost of operation is reduced because of the decrease in the volume of diluent used and the increase of the volume of oil shipped in the pipelines. The additives can be blended to a percentage of the amount of crude to be treated to improve flow assurance. In an embodiment, the additives reduce the amount of diluent required by 40-60%. The additives do not negatively effect on the pipeline seals or O-ring materials.

In an embodiment, the additives provide solutions to many hydrocarbon, paraffin, and asphaltene based problems. The additives combine a unique blend of surface-active compounds with various solubilization chemistries derived from an environmental waste stream. In an embodiment, the additives contain nano-surfactants. Due to their size, the nano-engineered reliquification particles drive the blend of liquefaction chemistries into deposits, providing superior dissolving and reliquification capabilities. Deposits across a vast spectrum, even with minimal flow or agitation, can be dissolved. In an embodiment, the additives, when applied batch-wise, are pumped as the leader followed by a flush of oil or water down the annulus, or in the case of gas lift wells, pumped down the tubing. In an embodiment, 1-10 gallons of the additives per foot of perforation is the recommended ratio for treatment. In an embodiment, the use of the additive is by a combination of circulation and soaking. In an embodiment, demulsification chemistries can be added to provide water separation in tanks as the oil is transferred from the well. In an embodiment, a continuous feed of additives can be used.

An embodiment of the disclosure is a heavy crude oil additive comprising a naphtha and a pyrolysis oil. In an embodiment, the heavy crude oil additive comprised of naphtha and pyrolysis oil reduces viscosity of the heavy crude oil. In an embodiment, the heavy crude oil additive comprised of naphtha and pyrolysis oil increases the API gravity of the crude oil. In an embodiment, the heavy crude oil additive comprised of naphtha and pyrolysis oil liquifies paraffin and/or asphaltene in heavy crude oil.

In an embodiment, pyrolysis oil is added at a pre-determined percentage into naphtha. In an embodiment, the combination of pyrolysis oil and naphtha can be added to heavy crude oil at a fixed percentage. In an embodiment, the fixed percentage is between 0.1 and 10%. The addition of the pyrolysis oil and naphtha combination to heavy crude oil can bring the viscosity of the heavy crude oil down to levels that allow the heavy crude oil to be transported through pumps and pipes. The addition of the combination also reduces the need for conventional naphtha (that does not contain pyrolysis oil) use by 20% to 60% while still obtaining similar viscosity levels of the heavy crude oil.

Pyrolysis oil is the by-product of pyrolysis, which is the heating of an organic material in the absence of oxygen, which decomposes into combustible gases. These combustible gases are condensed into a liquid called pyrolysis oil, bio-oil, bio-crude, or tire oil. Thermal deoxygenation (TDO) is a non-catalytic process using biomass to produce deoxygenated crude oils. During TDO, decomposition converts neutralized biomass hydrolysate to crude hydrocarbons. In an embodiment, the decomposition occurs in a reactor in the absence of oxygen at a temperature of 450° C. or more. The pyrolysis oil is comprised of hundreds of oxygenated, organic compounds including but not limited to carboxylic acids, ketones, aldehydes, furans, and sugars. In an embodiment, the pyrolysis is a catalytic process. In an embodiment, the catalyst is at least one of natural zeolite, synthetic zeolite (H-SDUSY), Al₂O₃ and Ca(OH)₂.

In an embodiment, the pyrolysis oil is from rubber, including but not limited to tires, rubber pipe, rubber cable, gum outsoles, telephone wire, and/or submarine cable. In an embodiment, other potential feedstocks include switchgrass, alfalfa stems, corn stover, corn cobs, barley straw, barley hulls, soybean straw, guayule, chicken litter, wood, and/or shale.

Performance increases provided by the addition of pyrolysis oil to naphtha can be significantly increased with the addition of a chemical additive blend. In an embodiment, the chemical additive blend is a mixture, including but not limited to, at least one of a terpene and/or terpenoid, citrus isolates, and surfactant chemistry. In an embodiment, the chemical additive comprises at least one terpenoid, at least one citrus isolate, and at least one surfactant.

In an embodiment, the chemical additive blend is added to the pyrolysis oil at between 0.1 and 20%.

Terpenes are classified by the number of isoprene units in the molecule and include, but are not limited to, the following:

-   -   Hemiterpenes: Consist of a single isoprene unit. Isoprene itself         is considered the only hemiterpene, but oxygen-containing         derivatives including, but not limited to, prenol and isovaleric         acid are hemiterpenoids.     -   Monoterpenes: Consist of two isoprene units and have the         molecular formula C₁₀H₁₆. Examples of monoterpenes and         monoterpenoids include, but are not limited to, geraniol,         terpineol, limonene, myrcene, linalool, or pinene. Iridoids are         derived from monoterpenes.     -   Sesquiterpenes: Consist of three isoprene units and have the         molecular formula C₁₅H₂₄. Examples of sesquiterpenes and         sesquiterpenoids include, but are not limited to, humulene,         farnesenes, and farnesol.     -   Diterpenes: Consist of four isoprene units and have the         molecular formula C₂₀H₃₂. They are derived from geranylgeranyl         pyrophosphate. Examples of diterpenes and diterpenoids include,         but are not limited to, cafestol, kahweol, cembrene, and         taxadiene.     -   Sesterterpenes: Have 25 carbons and five isoprene units. An         example includes, but is not limited to, geranylfarnesol.     -   Triterpenes: Consist of six isoprene units and have the         molecular formula C₃₅OH₄₈.     -   Sesquarterpenes: Consist of seven isoprene units and have the         molecular formula C₃₅H₅₆. Examples include, but are not limited         to, ferrugicadiol and tetraprenylcurcumene.     -   Tetraterpenes: Consist of eight isoprene units and have the         molecular formula C₄₀H₆₄. Examples include, but are not limited         to, acyclic lycopene, monocyclic gamma-carotene, and bicyclic         alpha- and beta-carotenes.     -   In an embodiment, citrus isolates are extracted from fruit         juices and oils from the rind of the fruit. In an embodiment,         the isolates are extracted from other plants. Isolate sources         include, but are not limited to, oranges, grapefruits,         tangerines, lemons, limes, myrcene, and pinene. Pinene, includes         but is not limited to, α-pinene.

Non-ionic surfactants include a hydrophilic head group and a hydrophobic tail. Nonionic surfactants do not have a charge on their hydrophilic head group. A wide variety of hydrophilic head groups are available in vesicle-forming surfactants. Various types of non-ionic surfactants include ethoxylates, alkoxylates, cocamides, ethoxylated aliphatic alcohols, polyoxyethylene surfactants, carboxylic esters, polyethylene glycol esters, anhydrosorbitol ester and its ethoxylated derivatives, glycol esters of fatty acids, carboxylic amides, monoalkanolamine condensates and polyoxyethylene fatty acid amides. In an embodiment, the surfactant has an optimized lipophilic tail.

The lipophilic tails of the surfactant ions remain inside the oil because they interact more strongly with oil than with water. The polar “heads” of the surfactant molecules coating the micelle interact more strongly with water, so they form a hydrophilic outer layer that forms a barrier between micelles. This inhibits the oil droplets, the hydrophobic cores of micelles, from merging into fewer, larger droplets (“emulsion breaking”) of the micelle. The compounds that coat a micelle are typically amphiphilic in nature, meaning that micelles can be stable either as droplets of aprotic solvents such as oil in water, or as protic solvents such as water in oil. When the droplet is aprotic, it is sometimes known as a reverse micelle.

An embodiment of the disclosure is a pyrolysis oil additive comprising at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants.

An embodiment of the disclosure is a heavy crude oil additive comprising a pyrolysis oil; at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants; and a naphtha.

In an embodiment, the additive to the crude oil is added between 0.1 and 20%. In an embodiment, the additive to the crude oil is added at between about 1 and about 10%. In an embodiment, the additive to the crude oil is added at between about 2 and about 8%. In an embodiment, the additive to the crude oil is added at between about 4 and about 6%. In an embodiment, the additive to the crude oil is added at about 4%.

An embodiment of the disclosure is a method of reducing viscosity of a heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a naphtha to form a second additive; and adding the second additive to the heavy crude oil to reduce the viscosity of the heavy crude oil. In an embodiment, the additive to the heavy crude is added to between 0.1 and 20%.

An embodiment of the disclosure is a method of increasing API gravity of heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a naphtha to form a second additive; and adding the second additive to the heavy crude oil to increase the API gravity of the heavy crude oil. In an embodiment, the additive to the heavy crude is added to between 0.1 and 20%.

An embodiment of the disclosure is a method of liquifying a substance in heavy crude oil comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a naphtha to form a second additive; and adding the second additive to the heavy crude oil to liquify a substance in the heavy crude oil. In an embodiment, the additive to the heavy crude is added to between 0.1 and 20%. In an embodiment, the substance to be liquified is at least one selected from the group comprising paraffin and asphaltene.

In an embodiment, the overall percentage of naphtha needed to reduce viscosity, increase API, and/or liquify paraffin and/or asphaltene in heavy crude oil is reduced with addition of the additives disclosed herein.

Advantages of the additives and methods disclosed herein are reduction of the amount of naphtha required to provide the same viscosity reduction; increase of the amount of pipeline compacity equal to the reduction in the amount of naphtha; providing a degree of control over paraffin and asphaltene precipitation and deposition; pyrolysis oil is compatible with the refinery process and adds British thermal unit (BTU) value; and providing of a degree of corrosion protection for the pipeline.

The above descriptions and embodiments can also be accomplished by substituting liquified petroleum gas (LPG) for naphtha in combination with pyrolysis oil.

In an embodiment, the disclosed heavy crude oil additives comprising pyrolysis oil added to naphtha or LPG can also be blended and injected with field gas. Field gas is natural gas extracted from a production well prior to entering the first stage of processing. In an embodiment, field gas means feedstock gas prior to entering a natural gas processing plant. Natural gas liquids are extracted from field gas at the natural gas processing plant. In an embodiment, “field gas” means “natural gas” or any derivative thereof, extracted from a production well, storage well, gathering system, pipeline, main or transmission line that is used as fuel to power field equipment.

In an embodiment, the disclosed compositions can be further blended and injected with CO₂.

In an embodiment, the disclosed compositions can be blended and directly injected above the pump or downhole for treatment of production crude.

In an embodiment, the disclosed compositions can be blended with liquid natural gas (LNG) and injected above the pump or downhole for the treatment of production crude.

In an embodiment, the disclosed compositions can be blended with diesel fuels.

In an embodiment, the disclosed compositions can be blended using fractional oils from the pyrolysis oils. Oil can be separated into different fractions using fractional distillation. A distillation column separates fractions by density and boiling point. In order of increasing density and boiling point, examples of fractions are C₁ to C₄ gases, C₅ to C₁₀ naphthas, C₅ to C₁₀ petrol, C₁₀ to C₁₆ kerosenes, C₁₄ to C₂₀ diesel oils, C₂₀ to C₅₀ lubricating oil, C₂₀ to C₇₀ fuel oils, and C70 residue.

In an embodiment, the disclosed compositions can be blended with zeolite and water soluble electrolyzed/hydrolyzed clinoptilolite fragments. Clinoptilolite is a natural zeolite composed of a microporous arrangement of silica and alumina tetrahedral. Zeolite/clinoptilolite can be used in oil and gas filtration. Zeolite/clinoptilolite can bind heavy metals. See US20170107121. The zeolite/clinoptilolite can be used to absorb a heavy metal toxin.

In an embodiment, the disclosed compositions can be blended with at least one of nanoparticles, zeolite, and markers. In an embodiment, a marker can be used to identify the source of a composition.

In an embodiment, the crude oil is bitumen.

In an embodiment, the disclosed compositions can be blended with a distillate.

In an embodiment, the disclosed compositions can be blended with taggant. See WO2012162701. In an embodiment, a taggant can be used to identify the source of a product. In an embodiment, the taggant is fluorescent. In an embodiment, the taggant can be a Stokes-shifting taggant. A Stokes-shifting taggant absorbs radiation at one wavelength and emits radiation at another wavelength. In an embodiment, the taggant is an indocyanine green complex.

In an embodiment, the disclosed compositions can be blended with iron nanoparticles.

In an embodiment, the disclosed compositions can be blended with methane, ethane, propane, butane, and combinations thereof.

In an embodiment, the disclosed compositions can be blended with kerosene.

In an embodiment, the disclosed compositions can be blended with marine bunker fuels.

EXAMPLES Example 1

Crude oil with a viscosity of 7,486 cSt at 60° C. was heated and maintained at 60° C. The additive of an additive of 95% naphtha and 5% pyrolysis oil was blended at a ratio of 4% to crude oil. The sample was maintained at 60° C. for homogenization. The sample was then analyzed for viscosity at 40° C., 60° C., and 100° C. FIG. 1, Table 1.

TABLE 1 3001-5 4% Parameter Result Viscosity, Kinematic, at 40° C., cSt, ASTM D 445.a, cSt 45,596.9 Viscosity, Kinematic, at 60° C., cSt, ASTM D 445.a, cSt 6,558.7 Viscosity, Kinematic, at 100° C., cSt, ASTM D 445.a, cSt 338.6

Example 2

Crude oil with a viscosity of 7,486 cSt at 60° C. was heated and maintained at 60° C. The VM+P (crude oil) naphtha additive was blended at a ratio of 8% to crude oil. All three samples were maintained at 60° C. for homogenization. The sample was then analyzed for viscosity at 40° C., 60° C., and 100° C.

TABLE 2 VM + P Naphtha Parameter Result Viscosity, Kinematic, at 40° C., cSt, ASTM D 445.a, cSt 17,222.9 Viscosity, Kinematic, at 60° C., cSt, ASTM D 445.a, cSt 2,536.3 Viscosity, Kinematic, at 100° C., cSt, ASTM D 445.a, cSt 174.5

FIG. 3 and Table 3 show kinematic viscosity (centistokes) at three different temperatures for an additive of 3001-5 (95% naptha, 5% tire pyrolysis oil) added to crude oil at a ratio of 8%.

FIG. 4 and Table 4 show kinematic viscosity (centistokes) at three different temperatures for an additive of 3001-10 (90% naptha, 10% tire pyrolysis oil) added to crude oil at a ratio of 8%.

TABLE 3 3001-5 (95% naphtha + 5% tire pyrolysis oil) Parameter Result Viscosity, Kinematic, at 40° C., cSt, ASTM D 445.a, cSt 23,487.7 Viscosity, Kinematic, at 60° C., cSt, ASTM D 445.a, cSt 2,002.2 Viscosity, Kinematic, at 100° C., cSt, ASTM D 445.a, cSt 176.4

TABLE 4 3001-10 (90% naphtha + 10% tire pyrolysis oil) Parameter Result Viscosity, Kinematic, at 40° C., cSt, ASTM D 445.a, cSt 35,236.4 Viscosity, Kinematic, at 60° C., cSt, ASTM D 445.a, cSt 2,071.8 Viscosity, Kinematic, at 100° C., cSt, ASTM D 445.a, cSt 219.4

Example 3

Elastomer compatibility, hardness, and relative volume change (ASTM D 471, using Viton O-Rings) of 3001-10 was measured. Table 5.

TABLE 5 Before After Hardness 75 75 Length, mm 41.63 41.63 Thickness, mm 3.53 3.53 Mass, g 0.7788 0.7788

Example 4

FIG. 5 depicts the colloidal instability index (CII) of four samples. The samples are CAN 10 (crude oil) (-diamond-); mix crude+naphtha (-square-); mix crude+UltraNaphtha (naphtha+pyrolysis oil) (-triangle-); and mix crude+UltraNaphtha (naphtha+pyrolysis oil) (-x-). See Table 6.

Table 6 and FIG. 5 depict the CII value for the three types of samples. In all cases, the CII value was between 0.7-0.9, which represents uncertainty in the stability of asphaltenes. However, 2073-01, 2073-02 and 2073-04 samples the CII value is close to 0.7, becoming these crudes less prone to precipitate asphaltenes.

TABLE 6 Colloidal Instability Sample Index (CII) CII (1978-03 M1) Can 10 0.84

>0.9 unstable (2073-01) Mix Crude + 0.72 0.7-0.9 meta-stable Naphtha (30% Naphtha + (or uncertain) 70% Crude) (2073-02) Mix Crude + 0.71 <0.7 stable Ultra Naphtha (1.2% Product + 28.8% Naphtha + 70% Crude) (2073-04) Mix Crude + 0.77 Ultra Naphtha (85% Crude + 14.4% Naphtha + 0.6% Product) (2073-01) Mix Crude + 0.69 Naphtha (30% Naphtha + 70% Crude) (2073-02) Mix Crude + 0.66 Ultra Naphtha (1.2% Product + 28.8% Naphtha + 70% Crude)

Table 7 provides the values for API gravity, asphaltene %, and kinematic viscosity among other values. The values are provided for various samples including crude oil; virgin naphtha; product 3001 (naphtha+pyrolysis oil); crude+naphtha; crude+naphtha+pyrolysis oil; and crude+naphtha+pyrolysis oil. Product 3001 is UltraNaphtha (2043-01).

TABLE 7 2073-02 Mix Crude + Ultra 2073-04 Mix 2073-01 Mix Naphtha (1.2% Crude + Ultra Crude + Product + Naphtha (0.6% Virgin Naphtha (30% 28.8% Product + 14.4% Crude Oil CAN10 Naphtha Product 3001 Naphtha + 70% Naphtha + 70% Naphtha + Parameter Method (1978-03 M1) (2054-01) (2043-01) Crude) Crude) 88% Crude) Water & Sediments Karl Fisher 0.045% wt 0.0045% wt 0.077% wt 0.0658% wt 0.0732% wt 0.1% wt ASTM D4377 Sediments ASTM 0.05% 0% wt 0% wt 0.04% 0.03% 0.02% D473 API Gravity 60° F. ASTM - D5002 7.4° API 61.9° API 21.9° API 19.6° API 22.1° API 13.5° API GE 1.0187 GE 0.7316 GE 0.9224 GE 0.9365 GE 0.9212 GE 0.9758 1.0177 g/cm3 0.7309 g/cm3 0.9215 g/cm3 0.9355 g/cm3 0.9203 g/cm3 0.9748 g/cm3 Saturates % ASTM D 2007 30.2 23.8 23 21.1 Aromatics % 34 31 30.6 20.4 Resins % 19.66 17.17 16.81 16.5 Asphaltenes % 15.1 109 10.6 13.6 Yield % 82.87 81.01 79.6 Molar composition ASTM D 7169/D — — — — by GC 7900 Kinematic ASTM D445. — 0.7809 mm2/s 12 174 mm2/s 295 61 mm2/s 126.39 mm2/s 4744.9 mm2/s Viscosity ASTM D 341 @5° C. @20° C. @ 30° C. @ 30° C. @30° C. 37687 mm2/s 0.6748 mm2/s 8 5424 mm2/s @50° C. @15° C. <30° C. 11619 mm2/s — — @60° C. Vapor REID ASTM D323 6.06 1.3 3.6 3.7 1.3 Pressure Salt Content ASTM D 3230 26.9 PTB 22.3 PTB 26.2 PTB 31.7 PTB Flash Point ASTM D93 87.6° C. Sulfur Content ASTM D4294 3.13% wt 2.436% wt 2.307% wt 2.76% wt TAN (Total Acid ASTM D684 2.42 mg KOH/g 1.77 mg 1.7 mg KOH/g 1.02 mg KOH/g Number) KOH/g Bottle tests API RP 42 — — — Material ASTM D 471 — — compatibility test

Table 8 shows a comparison of the obtained velocities.

TABLE 8 RESULTS 2073-02 Mix Crude + 2073-04 Mix Crude + 1978-03 2073-01 Mix Crude + Ultra Naphtha (1.2% Ultra Naphtha (85% M1 (CAN Naphtha (30% Product + 28.8% Crude + 14.4% PARAMETER 10) Naphtha + 70% Crude) Naphtha + 70% Crude) Naphtha + 0.6% Product) ° API Gravity 7.4 19.6 22.1 13.5 Viscosity, Kinematic, at 30° C., *N.D 295.61 125.39 4744.9 cSt, ASTM D 445.b, cSt * Viscosity, Kinematic, at 40° C., *N.D **N/A **N/A **N/A cSt, ASTM D 445.b, cSt * Viscosity, Kinematic, at 50° C., 37667 **N/A **N/A **N/A cSt, ASTM D 445.b, cSt * Viscosity, Kinematic, at 60° C., 11619 **N/A **N/A **N/A cSt, ASTM D 445.b, cSt *ND: The viscosity is not carried out at this temperature due to the Sample does not flow. **N/A This parameter is not included in the protocol.

Table 9 show the viscosity results after over 30 days of decantation.

TABLE 9 RESULTS 2073-01 Mix Crude + 2073-02 Mix Crude + Naphtha (30% Ultra Naphtha (1.2% Naphtha + Product + 28.8% PARAMETER 70 % Crude) Naphtha + 70% Crude) Viscosity, Kinematic, 478.36 470.36 at 30° C., cSt, ASTM D 445.b, cSt *

Table 10 shows the results for saturates, aromatics, resins, and asphaltenes after 30 days.

TABLE 10 RESULTS 2073-02 Mix Crude + 2073-01 Mix Crude + Ultra Naphtha (1.2% Naphtha (30% Product + 28.8% PARAMETER Naphtha + 70% Crude) Naphtha + 70% Crude) Saturates % wt. 17.40 17.30 Aromatics % wt. 29.70 28.80 Resins % wt 15.97 15.58 Asphaltenes % wt. 14.00 12.00 Yield % wt. 77.07 73.68

Conclusions include:

-   -   According to Table 8, at 30° C. the mix 2073-02 had a value         lower of 57.6% in comparison with the mix 2073-01.     -   Table 8 also shows that viscosity of the mix 2074-04 increase to         4744.9 cSt due the crude content was 85% and the naphtha and         UltraNaphtha accounted for 15%.     -   The viscosity for 2073-02 was lower than the standard value for         transportation of crude (max. 300cSt at 30° C. according to         OCENSA).     -   As it is shown in Table 7, the yield for the mix 2073-01,         2073-02 and 2073-04 was around 80%. Therefore, it can be         inferred that there were losses of saturates and aromatics         belonging to naphtha.     -   Table 7 also shows that the asphaltenes content for 2073-04         increased around 27% in comparison with 2073-01 and 2073-02,         which may be caused to the reduction of naphtha and UltraNaphtha         content.     -   Owing to both 2073-01 and 2073-02 accounted for 70% of the         mixture if it is calculated that percentage with the resins         value for the crude, it obtains a content of 13.76% wt.         Comparing this value with the resins for 2073-01 (17.17% wt.)         and 2073-02 (16.81% wt.) an increase is evidenced, therefore,         the naphtha may contain a higher resins content than the Crude.     -   As both 2073-01 and 2073-02 accounted for 70% of the mixture, if         the percentage with the asphaltenes value for the crude is         calculate, it is 10.57% wt. Comparing this value with the         asphaltenes for 2073-01 (10.90% wt.) and 2073-02 (10.60% wt.) is         evidenced that both mixtures did not significantly change their         asphaltenes content.     -   Table 6 and FIG. 5 depict the CII value for the three types of         samples. In all cases, the CII value was between 0.7-0.9, which         represents uncertainty in the stability of asphaltenes. However,         2073-01, 2073-02 and 2073-04 samples the CII value is close to         0.7, becoming these crudes less prone to precipitate         asphaltenes.     -   Table 9 shows viscosity results for the mix 2073-01 and 2073-02         after over 30 days. In contrast with Table 8, both increased by         around 474.36 cSt.     -   If the results from Table 7 are compared with Table 10, the         asphaltenes content of the mix 2073-02 only increased by 13.3%         and for the mix 2073-01 was 28.4%, after over 30 days.     -   After testing via Dräger tube, H₂S not detected in the tire oil.         Some mercaptan was present.

All of the compositions and methods disclosed and claimed herein can be made and executed without undue experimentation in light of the present disclosure. While the compositions and methods of this disclosure have been described in terms of preferred embodiments, it will be apparent to those of skill in the art that variations may be applied to the compositions and methods and in the steps or in the sequence of steps of the methods described herein without departing from the concept, spirit and scope of the disclosure. More specifically, it will be apparent that certain agents which are both chemically related may be substituted for the agents described herein while the same or similar results would be achieved. All such similar substitutes and modifications apparent to those skilled in the art are deemed to be within the spirit, scope and concept of the disclosure as defined by the appended claims. 

What is claimed is:
 1. A heavy crude oil additive comprising a naphtha; and a pyrolysis oil.
 2. The heavy crude oil additive of claim 1 further comprising at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants.
 3. A method of using the heavy crude oil additive of claim 1 comprising adding the heavy crude oil additive to heavy crude oil to achieve at least one of the following: reduce the viscosity of the heavy crude oil, increase the API gravity of the heavy crude oil, or liquify a substance in the heavy crude oil.
 4. The method of claim 3 wherein the substance is at least one selected from the group comprising paraffin and asphaltene.
 5. A method of preparing the composition of claim 2 comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a naphtha to form a second additive; and adding the second additive to the heavy crude oil.
 6. The method of claim 5 wherein the second additive is added to the heavy crude oil at between about 0.1 and about 20%.
 7. The method of claim 6 wherein the second additive is added to the heavy crude oil at between about 2 and about 8%.
 8. The method of claim 7 wherein the second additive is added to the heavy crude oil at about 4%.
 9. The composition of claim 2 further comprising at least one selected from the group consisting of associated field gas, CO₂, liquid natural gas, diesel fuels, fractional oils from pyrolysis oils, zeolite and electrolyzed/hydrolyzed clinoptilolite fragments, a taggant, iron nanoparticles, methane, ethane, propane, butane, kerosene, marine bunker fuels, and combinations thereof.
 10. The composition of 9 where the taggant is a Stokes shift taggant.
 11. A pyrolysis oil additive comprising at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants.
 12. A method of preparing the composition of claim 11 comprising combining at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants.
 13. A heavy crude oil additive comprising liquified petroleum gas; a pyrolysis oil; and at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants.
 14. A method of using the heavy crude oil additive of claim 13 comprising adding the heavy crude oil additive to heavy crude oil to achieve at least one of the following: reduce the viscosity of the heavy crude oil, increase the API gravity of the heavy crude oil, or liquify a substance in the heavy crude oil.
 15. The method of claim 13 wherein the substance is at least one selected from the group comprising paraffin and asphaltene.
 16. A method of preparing the composition of claim 13 comprising adding at least one selected from the group comprising a terpene, one or more citrus isolates, and one or more non-ionic surfactants to a pyrolysis oil to form a first additive; adding the first additive to a liquified petroleum gas to form a second additive; and adding the second additive to the heavy crude oil.
 17. The method of claim 16 wherein the second additive is added to the heavy crude oil at between about 0.1 and about 20%.
 18. The method of claim 17 wherein the second additive is added to the heavy crude oil at between about 2 and about 8%.
 19. The composition of claim 18 further comprising with at least one selected from the group consisting of associated field gas, CO₂, liquid natural gas, diesel fuels, fractional oils from pyrolysis oils, zeolite and electrolyzed/hydrolyzed clinoptilolite fragments, a taggant, iron nanoparticles, methane, ethane, propane, butane, kerosene, marine bunker fuels, and combinations thereof.
 20. The composition of claim 19 wherein the taggant is a Stokes shift taggant. 